To obtain hydrocarbon fluids from an earth formation, a wellbore is drilled into an area of interest within a formation. The wellbore may then be “completed” by inserting casing in the wellbore and setting the casing using cement. Alternatively, the wellbore may remain uncased as an “open hole,” or it may be only partially cased. Regardless of the form of the wellbore, production tubing is run into the wellbore to convey production fluid (e.g., hydrocarbon fluid, which may also include water) to the surface.
Often, pressure within the wellbore is insufficient to cause the production fluid to naturally rise through the production tubing to the surface. In these cases, an artificial lift system can be used to carry the production fluid to the surface. One type of artificial lift is a gas lift system, of which there are two primary types: tubing-retrievable gas lift systems and wireline-retrievable gas lift systems. Each type of gas lift system uses several gas lift valves spaced along the production tubing. The gas lift valves allow gas to flow from the annulus into the production tubing so the gas can lift production fluid in the production tubing. Yet, the gas lift valves prevent fluid to flow from the production tubing into the annulus.
In gas lift, high-pressure gas is injected into the production conduit of the well in a continuous fashion to reduce the backpressure on the formation by reducing the hydrostatic load of the production fluid. Gas lift can also be used in a cyclic manner to displace well fluid to the surface by displacing a fluid slug with an expanding high-pressure gas bubble that lifts the slug to the surface. A major component in a gas lift system is the gas lift valve. The gas lift valve is used to communicate the injection gas form the annulus into the tubing string. Various types of gas lift valves exist to meet various operating parameters of the well.
A typical wireline-retrievable gas lift system 10 is shown in FIG. 1. Operators inject compressed gas G into the annulus 22 between a production tubing string 20 and the casing 24 within a cased wellbore 26. A valve system 12 supplies the injection gas G from the surface and allows produced fluid to exit the gas lift system 10.
Side pocket mandrels 30 spaced along the production string 20 hold gas lift valves 40 within side pockets 32. As noted previously, the gas lift valves 40 are one-way valves that allow gas flow from the annulus 22 into the production string 20 and prevent gas flow from the production string 20 into the annulus 22.
In operation, the production fluid P flows from the formation into the wellbore 26 through casing perforations 28 and then flows into the production tubing string 20. A production packer 14 located on the production string 20 forces the flow of production fluid P from a formation up through the production string 20 instead of up through the annulus 22. When it is desired to lift the production fluid P, compressed gas G is introduced into the annulus 22. The production packer 14 forces the gas flow from the annulus 22 into the production string 20 through the gas lift valves 40. In particular, the gas G enters from the annulus 22 through ports 34 in the mandrel's side pockets 32. Disposed inside the side pockets 32, the gas lift valves 40 then control the flow of injected gas I into the production string 20. As the injected gas I rises to the surface, it helps to lift the production fluid P up the production string 20 to the surface.
A typical gas lift valve 40A used in the art for a wireline-retrievable system is shown in FIG. 2A. The gas-lift valve 40A has upper and lower seals 44a-b separating vale ports 46, which communicate with injection gas ports 48. A valve piston 52 is biased closed by a gas charge dome 50 and a bellows 56. At its distal end, the valve piston 52 moves relative to a valve seat 54 at the valve ports 46 in response to pressure on the bellows 56 from the gas charge dome 50. A predetermined gas charge applied to the dome 50 and bellows 56 therefore biases the valve piston 52 against the valve seat 54 and close the valve ports 46.
A check valve 58 in the gas-lift valve 40 is positioned downstream from the valve piston 52, valve seat 54, and valve ports 46. The check valve 58 keeps flow from the production string (not shown) from going through the injection ports 48 and back into the casing (annulus) through the valve ports 46. Yet, the check valve 58 allows injected gas from the valve ports 46 to pass out the gas injection ports 48.
An alternative type of gas lift valve 40B is shown in FIG. 2B. This valve 40B is similar to that disclosed in U.S. Pat. Pub. No. 2010/0096142, entitled “Gas-Lift Valve and Method of Use.” Briefly, this valve 40B is like an inverted form of the typical gas-lift valve. The valve 40B has inlet ports 46 and a valve seat 54. However, the valve's outlet port 43 is disposed at the upper end of the valve 40B as opposed to being at the downhole end. A tubular latch 42 at the top of the valve 40B has a removable plug (not shown) that can dispose in the outlet port 43.
Internally, the valve 40B has a gas charged dome 50, a valve ball member 52, and a bellows 56 positioned below the valve seat 54, as opposed to disposing in the traditional arrangement above the valve seat. The purpose of this inverted gas lift valve 40B is to redirect the injection gas out of the valve's uphole outlet 43 in an upward direction so the injected gas flows along with the natural flow of the tubing string. This upward injection is believed to increase production.
Other types of downhole devices, which are not gas lift valves, can install in side pocket mandrels. For example, “dummy” valves can install in the side pocket of a mandrel. These dummy valves are not actually valves because they merely dispose in the mandrel to seal of the mandrel's ports so pressure testing can be performed.
As shown in FIG. 3, a circulating device 40C is another device that can dispose in a mandrel downhole. Similar to an RC-1 DC circulating device available from Weatherford International, the circulating device 40C has inlets 46 at a central portion of the device's housing. Upper and lower outlets 41a-b on the device 40C communicate with these central inlets 46, and packing seals 44a-b disposed about the device 40C isolate the inlets 46 when installed in a mandrel.
Internally, the circulating device 40C lacks loaded valve mechanisms and instead merely has check darts 45a-b and seats 47a-b. Fluids entering the inlets 46 from a borehole annulus can pass the check darts 45a-b and seats 47a-b and can proceed unhindered out the outlets 41a-b. The check darts 45a-b simply restrict reverse flow from the tubing past the seats 47a-b. Being unloaded, this device 40C is essentially not capable of closing off inlet flow so it cannot be used as an unloading valve of injected gas in a gas lift operation.
High rate wells typically need high gas volumes for gas lift to work. To meet this need, the gas lift system must inject very large volumes of gas so gas lift valves with large injection ports are used. Understandably, the size of the gas lift valve limits the available size for the injection ports so that larger and larger valve sizes are needed to provide the required larger injection ports. Ultimately, the size of the production casing and size of the tubing string limits the size of the gas lift valve that can be used.
As an additional problem, high rate wells require large tubing sizes to produce efficiently. The increased tubing size reduces the amount of available room between the production casing and tubing string and limits the size of the gas lift valves that can be installed. In fact, gas lift valves that can meet large injection volumes are being manufactured that prove difficult to fit into the completion.
In some situations in a high rate well, an operator has to run smaller valves (i.e., a valve having 1-in. OD) downhole because of the casing clearance in the borehole. To improve gas injection, the operator runs a mandrel with multiple pockets or runs two standard mandrels separated by a joint of pipe on the tubing string in the borehole. In this way, the smaller valves installed in the pockets of the mandrel(s) can provide double the gas passage. As expected, the multiple valves, pockets, and mandrels significantly complicates servicing the completion.
The subject matter of the present disclosure is directed to overcoming, or at least reducing the effects of, one or more of the problems set forth above.